Absorption systems have been designed to selectively remove a gaseous component from a gas stream by absorption into an absorbent solution. In many, if not most of these systems, the absorbent solution also absorbs other gaseous components contained in the gas stream but at a different rate from that of the desired gaseous component. The rates of absorption of the various gaseous components into the absorbent solution are a function of time. Consequently the relative concentrations of the gaseous components in the absorbent solution will depend on the length of time the gases contact the liquid absorbent, i.e. the residence time of the gas in an absorption zone (volume) where intimate gas-liquid contact occurs. Since these absorption systems are designed to achieve particular relative concentrations of absorbed gaseous components from a gas stream flowing at a particular rate, such absorption systems are thrown into disruption whenever the gas flow rate changes. This difficulty will be discussed hereinafter particularly as it pertains to the selective removal of H.sub.2 S from a gas stream.
The removal of H.sub.2 S from a gas stream is a problem that has long confronted workers in many diverse industries. For example, the manufactured gas industry and the coke-making industry, which commonly produce coal gas containing unacceptable amounts of H.sub.2 S by the destructive distillation of coal, have a need to remove the H.sub.2 S. Other examples are the natural gas industry where the H.sub.2 S content of many gas streams is often too high for commercial acceptance and the petroleum industry where the crude oil to be refined into various products contains a minor amount of sulfur in the form of various sulfur compounds.
The removal of H.sub.2 S has been accomplished in the prior art in numerous ways which usually involve one of the following techniques: (1) selective absorption of H.sub.2 S into a wide variety of liquid absorbent solutions which can then be regenerated to afford a concentrated H.sub.2 S gas stream for further processing in a sulfur recovery system; (2) adsorption on a solid adsorbent with eventual conversion of the adsorbed H.sub.2 S into a readily removable sulfur-containing product; and (3) selective reaction of H.sub.2 S with a suitable chemical reagent which produces an easily separable sulfur containing product.
Of the techniques in the first category, probably the most efficient H.sub.2 S removal process utilizes alkanolamines in aqueous absorbent solutions. However, the removal of H.sub.2 S becomes complicated by the fact that the gas stream frequently contains CO.sub.2 which is a slightly stronger acid. H.sub.2 S tends to be preferentially absorbed into the basic alkanolamine absorbent solutions, but when equilibrium is established through extended contact time between the absorbent solution and the gas stream, the relative amount of absorbed CO.sub.2 increases.
For example, coke oven gas, which contains H.sub.2 S and CO.sub.2 in addition to other gaseous components, may be treated with an aqueous monoethanolamine (MEA) solution to remove substantially all of the H.sub.2 S present utilizing any suitable absorption apparatus such as a packed tower absorber, a spray contact apparatus, a bubble tray absorber and the like. The H.sub.2 S will react almost instantaneously upon contact with the aqueous MEA solution to form monoethanolamine sulfide or hydrosulfide which may then be decomposed by the application of heat to the solution prior to or simultaneous with the stripping of the H.sub.2 S from the solution, for example by the use of steam in the desorption stage.
Carbon dioxide, on the other hand, takes a significant, finite time to react with the water in the MEA solution to form carbonic acid according to the well-known equilibrium reaction prior to reacting with the MEA to form a monoethanolamine carbonate or bicarbonate. Thus the CO.sub.2 does not tend to be taken up by the MEA solution as readily, and is consequently not removed from the gas stream as quickly as the H.sub.2 S. In general, it may be simplistically stated that the molar ratio of H.sub.2 S to CO.sub.2 absorbed in the absorbent solution will depend principally upon the gas-liquid contact volume and the residence time of the gas in this absorption volume. By controlling the throughput, or flow rate, of the gas to the absorber so that only a portion of the CO.sub.2 has time to be absorbed, the relative amount of CO.sub.2 and H.sub.2 S taken up by the absorbent solution can be controlled so that almost all of the H.sub.2 S content of the gas is absorbed while less than the total available CO.sub.2 is absorbed into the MEA. Since H.sub.2 S is absorbed at a much greater rate into an alkaline absorbent than does CO.sub.2 and if the absorption step is conducted under non-equilibrium conditions in a manner such that the gas stream is only in contact with the absorbent solution for a relatively short period of time (i.e. relative to the time for an equilibrium condition to be established), some selectivity for H.sub.2 S can be obtained if larger amounts of H.sub.2 S can be tolerated in the treated gas stream than would otherwise be present with a longer contact time. So long as the throughput of the gas to the absorber is relatively constant and is significantly faster than the time required to absorb all of the CO.sub.2 into the solution, the ratio of H.sub.2 S and CO.sub.2 absorbed will tend to remain substantially constant. The unabsorbed CO.sub.2 leaves the absorption apparatus along with any other unabsorbed gases which may be present in the exhausted "sweet", or desulfurized coke oven gas.
Hydrogen sulfide removal and sulfur recovery systems for removing H.sub.2 S from coke oven gas (COG) are designed with the above factors in mind. The absorption capacity, or volume, in which the gas stream and absorbent solution are intimately contacted must be dimensioned to accommodate and desulfurize the maximum COG flow that can be expected from the coke oven batteries. Any lesser capacity would result in significant concentrations of H.sub.2 S in the desulfurized sweetened COG and eventual pollution of the environment. In conjunction with the absorption capacity, the flow rate of the lean absorbent solution is preferentially selected to absorb H.sub.2 S:CO.sub.2 in a molar ratio of greater than 1:3 and to produce a fully loaded or rich absorbent solution to maximize the efficiency of the desorption stage.
The loaded absorbent from the absorption apparatus is passed to a desorption apparatus to thermally drive the absorbed gases out of the absorbent solution to yield regenerated or lean absorbent for recycling to the absorption zone and an H.sub.2 S and CO.sub.2 containing desorbed acid gas stream which is usually directed to a sulfur recovery plant. In many cases sulfur recovery is accomplished in a Claus plant where SO.sub.2 is mixed with the desorbed gas stream. The necessary SO.sub.2 can be produced by burning an appropriate amount of the H.sub.2 S or, alternatively, a portion of the final sulfur product from the Claus plant. The SO.sub.2 reacts with the H.sub.2 S to produce elemental sulfur according to the well-known equation EQU 2H.sub.2 S+SO.sub.2 .fwdarw.3S+2H.sub.2 O.
The above described H.sub.2 S removal and sulfur recovery system and similar systems for the selective removal of H.sub.2 S from gases that contain H.sub.2 S and CO.sub.2, and possibly one or more other components, are well-known. The selectivity of such systems is based on differences in absorption velocity of H.sub.2 S and CO.sub.2 and is ensured by reducing to a sufficient extent the contact time between the gas and the absorbent solution. The flexibility of such processes is very limited, however. When the feed gas flow rate or throughput decreases in a given absorption system, the contact or residence time immediately increases with a consequent lowering of the selectivity because the absorption process moves in the direction of equilibrium conditions for the absorption of CO.sub.2 and results in a decreasing H.sub.2 S:CO.sub.2 absorption ratio. Upon desorption, the increased CO.sub.2 content of the desorbed gas stream may reach such a concentration that it dilutes the H.sub.2 S-SO.sub.2 combustion mixture to a degree such that the Claus plant becomes inoperative.
In a coking operation, for example, the COG flow from the coke ovens will often vary below the maximum COG flow for which the absorption system was designed. As coke oven batteries are shut down or coking rates are reduced, the COG flow to the absorber may quickly be reduced to such a level as to interfere with the subsequent Claus process. The flow rate of COG or any H.sub.2 S and CO.sub.2 containing gas at which this problem arises in relation to the maximum gas flow rate which the absorption system was designed to treat can be termed the critical feed gas flow rate.
Although the liquid absorbent flow rate as a practice is proportioned to the gas flow rate, the liquid absorbent flow rate cannot be significantly varied with the hope of altering the contact time between the gas and the absorbent solution because the packing or bubble-cap trays within the absorption column are designed to permit a limited range of liquid flow rate through the column as are the pumps and piping. Moreover, the gas flow rate through the absorption volume, which flow determines the gas residence time, is the principal factor affecting contact time, not the absorbent flow. Regardless of how fast the absorbent solution is passing through the absorption volume, the gas stream from which H.sub.2 S is to be removed will have a particular residence time in the absorption volume dependent upon the rate of the gas flowing through the absorption volume. During the time the gas is within the absorption volume it is contacting absorbent solution. Since the COG flow changes with the varying coke production requirements and whatever COG that is produced must be treated when produced, controlling the residence time by controlling the flow rate of the COG is impossible.
Accordingly, there is a need to selectively remove a gaseous component from a gas stream having a variable flow rate by absorption into an absorbent solution which also absorbs another gaseous component of the gas stream but at a different rate of absorption. Particularly, there is a need to selectively absorb H.sub.2 S with an absorbent solution from a gas stream having a variable flow rate and containing H.sub.2 S and CO.sub.2 so as to maintain or control the relative concentration of H.sub.2 S and CO.sub.2 in the absorbent solution. More particularly, there is a need to maintain the concentration of H.sub.2 S in the acid gas stream derived from the treatment of COG so that a downstream Claus plant will not become inoperative when the COG flow rate significantly decreases.